Rotating drilling stabilizer

ABSTRACT

A stabilizer and method for use in a wellbore are disclosed. The apparatus can include a rotary body disposed about a tubular and configured to rotate and axially-translate with respect to the tubular. The apparatus can also include a first anti-rotation device disposed axially adjacent the rotary body and configured to resist rotation and axial translation with respect to the tubular. The rotary body can be configured to engage the first anti-rotation device and rotationally lock therewith. The apparatus can also include a biasing member configured to bias apart the rotary body and the first anti-rotation device.

BACKGROUND

A bottom hole assembly (“BHA”) is a drilling tool or combination ofdrilling tools typically configured for use at the distal or downholeend of a drill string. More particularly, the BHA is generally theportion of the drill string extending from a distal end of the drillpipe. The BHA can include one or more subs made up together, with eachsub providing a specific tool or structure. For example, a conventionalBHA can include one or more drill bits, stabilizers, reamers, shocks,hole openers, drill collars, combinations thereof, and the like.Further, BHAs can include mud motors and can be steerable, for example,to assist in changing a direction of the wellbore in directionaldrilling applications.

BHAs can be “slick,” i.e., can generally have no stabilizing devices;however, this can lead to undesired vibration. Accordingly, stabilizersare commonly employed as part of BHAs to avoid such vibration and canalso assist in directional control. Such directional control can enablethe driller to maintain or avoid pendulum forces and/or can be used inpacked hole assemblies. To this end, stabilizers can be employed invertical drilling, to maintain a constant direction, and in deviated ordirectional drilling, to provide control of directional changes in thewellbore. Various BHAs and stabilizers are suitable for use in either orboth applications and are commonly employed.

The use of stabilizers to aid in directional control, however, presentsseveral challenges. Stabilizers often slide against the wellbore wall,resulting in wear on the stabilizer and increasing drag on the advancingof the drill string. Further, such increased drag can even result in thestabilizer being hung-up on ledges or other partial wellboreobstructions. Overcoming the drag forces can, at least temporarily,reduce the weight on the drill bit (WOB) and slow the drilling process.Further, the stabilizers can increase torsional vibration (“stickslip”), especially in “non-rotational” stabilizers (i.e., stabilizersrotationally fixed to the drill string so as to rotate therewith withrespect to the wellbore). Such vibration can be damaging to the BHA.

Roller reamers have been employed in an attempt to overcome some ofthese challenges. Roller reamers generally include a stabilizer withroller bearings or wheels on the outside diameter, so as to reducefriction resulting from the stabilizer engaging the wellbore. Suchroller reamers can reduce drag and torsional vibration, but can also besensitive to drill string vibration or other upsets and can losebearings downhole. Such losses (often referred to as “junk” or “fish”)can lead to the roller reamers becoming less effective and can cost rigtime as the lost structures can necessitate fishing operations to removethe structures from the wellbore.

What is needed are improved apparatus and methods for stabilizing abottom hole assembly.

BRIEF SUMMARY

In various aspects, the disclosure can provide a stabilizer having arotary body and one or more, for example, two stationary bodies. Therotary body can be configured to rotate about a tubular, whether thetubular is stationary or rotating with respect to a stationary referenceplane. For example, while the tubular rotates with respect to astationary reference plane, the rotary body can remain generallyrotationally stationary with respect to the wellbore, although it can befree to rotate as needed. The rotary body can be centralized between thetwo stationary bodies by one or more biasing members. The stationarybodies can be stationary with respect to the tubular, i.e., can movealong with the tubular. If the rotary body encounters a ledge or otherpartial wellbore obstruction, the obstruction can apply an axial forceon the rotary body that can overcome the centralizing force applied bythe biasing member and can cause the rotary body to slide, in somecases, into engagement with one of the stationary bodies.

The stationary bodies can each include an anti-rotation device, whichcan rotationally lock with the rotary body, such that the rotary bodyand the stationary body can resist rotation relative one another.Accordingly, turning of the tubular and/or application of axial force onthe drill string can cause the rotary body to cut, grind, or otherwiseremove the wellbore obstruction, freeing the stabilizer to pass by. Withthe wellbore obstruction removed, the biasing member can urge the rotarybody to slide out of engagement with the stationary body, allowing therotary body to recommence generally free rotation with respect to thetubular.

Embodiments of the disclosure can provide a stabilizer apparatus for usein a wellbore. The apparatus can include a rotary body disposed about atubular. The apparatus can also include a first anti-rotation devicedisposed axially adjacent the rotary body and configured to resistrotation and axial translation with respect to the tubular. The rotarybody can be configured to slide axially to engage the firstanti-rotation device and rotationally lock therewith. The apparatus canalso include a biasing member configured to bias apart the rotary bodyand the first anti-rotation device.

Embodiments of the disclosure can also provide a method for stabilizinga drill string. The method can include biasing the rotary body disposedon a tubular axially apart from a first stationary body disposed axiallyadjacent the rotary body. The method can also include radially engaginga wellbore wall with an outer diameter of the rotary body so as tocentralize the drill string. The method can further include sliding therotary body toward the first stationary body in response to an axialforce, and rotationally locking the rotary body and the first stationarybody.

Embodiments of the disclosure can also provide a stabilizer for a drillstring. The stabilizer can include a rotary body disposed about atubular of the drill string and having first and second axial ends, andan outer diameter configured to engage a wellbore. The stabilizer canalso include a first stationary body disposed axially adjacent the firstaxial end of the rotary body and including a first anti-rotation deviceconfigured to rotationally lock with the rotary body. The firststationary body can be configured to resist axial translation androtation with respect to the tubular. The stabilizer can also include asecond stationary body disposed axially adjacent the second axial end ofthe rotary bod and including a second anti-rotation device configured torotationally lock with the rotary body. The second stationary body canbe configured to resist axial translation and rotation with respect tothe tubular. The stabilizer can further include one or more biasingmembers configured to bias the rotary body to a position intermediateand axially offset from both the first and second stationary bodies. Therotary body can be free to rotate with respect to the tubular unlessrotationally locked with the first stationary body or the secondstationary body.

BRIEF DESCRIPTION OF THE DRAWINGS

Various features of the embodiments can be more fully appreciated, asthe same become better understood with reference to the followingdetailed description of the embodiments when considered in connectionwith the accompanying figures, in which:

FIG. 1 illustrates a schematic, side view of a stabilizer, according toan embodiment.

FIGS. 2-4 illustrate simplified, schematic, side views of thestabilizer, depicting one example of operation of the stabilizer beingdeployed into a wellbore, according to an embodiment.

FIGS. 5A and 5B illustrate quarter-sectional views of the stabilizerincluding a secondary anti-rotation device, according to an embodiment.

FIG. 6 illustrates a quarter-sectional view of the stabilizer, withanother embodiment of the secondary anti-rotation device.

FIG. 7 illustrates a flowchart of a method for stabilizing a drillstring in a wellbore, according to an embodiment.

DETAILED DESCRIPTION

While the present disclosure has been described according to itspreferred embodiments, it is of course contemplated that modificationsof, and alternatives to, these embodiments, such modifications andalternatives obtaining the advantages and benefits of this disclosure,will be apparent to those of ordinary skill in the art having referenceto this specification and its drawings. It is contemplated that suchmodifications and alternatives are within the scope of this disclosureas subsequently claimed herein.

FIG. 1 illustrates a schematic, side view of a stabilizer 100, accordingto an embodiment. The stabilizer 100 can be disposed about a tubular102, which can form part of or be connected to a drill string and can beconfigured to be disposed in a wellbore. It will be appreciated that thetubular 102 can include one or more pipes, mandrels, segments, subs, orbodies and can be cylindrical or can have a non-circular cross-section(e.g., elliptical). Furthermore, the stabilizer 100 can include a rotarybody 104 and one or more stationary bodies (for example, two are shown:106, 108). As the terms are used herein, “rotating,” “rotatable,”“rotary,” and “stationary” are generally considered to be taken with thetubular 102 as the point of reference, and it will be appreciated thatthe tubular 102 itself can be rotating with respect to a stationaryreference plane and can be advancing axially in the wellbore. The“rotary” body 104 can free to rotate with respect to the tubular 102,unless, for example, the rotary body 104 is rotationally locked, as willbe described in greater detail below.

The rotary body 104 can have axial ends 110, 112 and an outer diameter113. The rotary body 104 can be disposed axially between or“intermediate” the stationary bodies 106, 108, such that the axial ends110, 112 can face the stationary bodies 106, 108, respectively, whilethe outer diameter 113 faces radially outwards. In some embodiments, asingle stationary body 106 or 108 can be employed, while omitting theother stationary body 106 or 108. Furthermore, in other embodiments,additional stationary bodies can be employed for a variety of purposes,as will be readily understood by one with skill in the art.Additionally, the outer diameter 113 of the rotary body 104 can belarger than an outer diameter of the stationary bodies 106, 108, asshown.

The rotary body 104 can also include cutting surfaces 110A, 112A, forexample, on or adjacent to the axial ends 110, 112 or elsewhere on therotary body 104. The cutting surfaces 110A, 112A can be a high-frictioncoating, such as a tungsten carbide coating. In other embodiments,buttons of high-strength cutting material can be embedded in the axialends 110, 112 to provide the cutting surfaces 110A, 112A. In yet otherembodiments, the cutting surfaces 110A, 112A can be an edge between oneor both of the axial ends 110, 112 and the outer diameter 113. Oneskilled in the art will realize that the cutting surface 110A, 112A canbe formed of any material and formed in any configuration thatfacilitates removal of material from the wellbore.

The juncture between the axial ends 110, 112 and the outer diameter 113can form one example of the cutting surface 110A, 112A, which can definean attack angle a. The attack angle a can be defined as the anglebetween a line parallel to the cutting surface 110A, 112A and a lineparallel to the outer diameter 113. A range of cutting angles a can beemployed, for example, between about 120° and about 0°. However, in someembodiments, cutting efficiency of the rotary body 104 can be maximizedwith reduced cutting angles, for example, less than about 20°.

The rotary body 104 can further include an inner diameter that can belarger than the outer diameter of the tubular 102, e.g., to enablerelative rotation between the rotary body 104 and the tubular 102.Friction-reducing members, such as bearings, can be disposed between therotary body 104 and the tubular 102, to facilitate such relativerotation. The inner diameter can be cylindrical or can have one or morenon-circular cross-sectional shapes.

The stationary bodies 106, 108 can each include an anti-rotation device114, 115, respectively, and a base 116, 117, respectively. Theanti-rotation devices 114, 115 can extend axially from the bases 116,117 and toward the rotary body 104, as shown. In at least oneembodiment, the bases 116, 117 can be stop collars fixed to the tubular102 in any suitable manner, for example, by resistance fit, welding,brazing, set screws, pins, or other fasteners, adhesives, teeth,combinations thereof, or the like. In another embodiment, one or more ofthe bases 116, 117 can be a pipe joint or can otherwise be integrallyformed with the tubular 102. The anti-rotation devices 114, 115 can becoupled to the bases 116, 117, respectively, such that the anti-rotationdevices 114, 115 can be constrained from rotating with respect to thetubular 102. Accordingly, the stationary bodies 106, 108 can bepositionally fixed to the tubular 102, such that, in general, thestationary bodies 106, 108 can resist relative axial translation androtation with respect to the tubular 102. In some embodiments, however,a range of axial motion of the anti-rotation devices 114, 115 can beprovided, while the stationary bodies 106, 108 can still be consideredpositionally fixed with respect to the tubular 102, as the term is usedherein.

The stabilizer 100 can also include one or more biasing members (two areshown: 118, 120), which can extend between the axial ends 110, 112 ofthe rotary body 104 and the stationary bodies 106, 108, respectively.The biasing members 118, 120 can apply centralizing forces on the rotarybody 104, such that the rotary body 104 can be, at a default, maintainedbetween and axially offset from both of the stationary bodies 106, 108.The biasing members 118, 120 can thus prevent the rotary body 104 fromengaging either anti-rotation devices 114, 115 until an externallyapplied force overcomes the biasing force applied by the biasing members118, 120.

The biasing members 118, 120 can be or include one or more tensionsprings, one or more compression springs, leaf springs, resilientelastomeric members, magnets, combinations and/or arrays thereof, or anyother structure capable of applying an axial centralizing force on therotary body 104. Accordingly, in various embodiments, the biasing member118 can bias the second stationary body 108 from the rotary body 104,while the biasing member 120 can bias the first stationary body 106 fromthe rotary body 104. In other embodiments, the biasing member 118 canbias the first stationary body 106 from the rotary body 104, while thebiasing member 120 can bias the second stationary body 108 from therotary body 104. Furthermore, in some embodiments, the biasing members118, 120 can cooperate to provide a centralizing force on the rotarybody 104, such that both can serve to bias the rotary body 104 from thestationary bodies 106, 108. In still other embodiments, a single biasingmember can be employed to apply the centralizing force. Further,although a single biasing member 118, 120 is shown on each side of therotary body 104, it will be appreciated that each biasing member 118,120 can include multiple biasing members.

In various embodiments, the biasing force applied by one or more of thebiasing members 118, 120 can range from about 1,000 lbs to about 2,000lbs. In some embodiments, the biasing force can be determined at leastaccording to how many stabilizers 100 are deployed in a drill string.Further, the biasing force can be controlled and/or selected accordingto how many and what type of biasing members 118, 120 are utilized withthe rotary body 104. For example, a lower biasing force can be suitablewhen more stabilizers 100 are used. Without being limited to theory, thebiasing force can also act generally according to Hooke's law, such thatthe force varies according to the position of the rotary body 104.

The rotary body 104 can also include engaging members which can beconfigured to engage the anti-rotation devices 114, 115 so as to resistrelative rotation between the rotary body 104 and the stationary bodies106, 108. In one embodiment, the engaging members of the rotary body 104can extend radially, either toward or away from the tubular 102. Suchradially-oriented engaging members can include teeth, forming, forexample, a gear. In such an embodiment, the anti-rotation devices 114,115 can also include teeth, for example, so as to form a spline gear.Accordingly, the rotary body 104 can be configured to slide at leastpartially over the anti-rotation devices 114, 115, such that theengaging members rotationally lock, enmesh, or otherwise engage theanti-rotation devices 114, 115 so as to resist rotation relativethereto. In another radial embodiment, the engaging members can be ahigh-friction surface disposed on the inside diameter of the rotary body104. In at least one such embodiment, the anti-rotation devices 114, 115can also include a high-friction surface, such that an engagementbetween one of the engaging members and one of the anti-rotation devices114, 115 forms a brake. Indeed, it will be appreciated that theanti-rotation devices 114, 115 may be or include any suitable deviceconfigured to reduce, slow, eliminate, or otherwise resist relativemotion of the rotary body 104 with respect to the tubular 102, when therotary body 104 and at least one of the anti-rotation devices 114, 115are engaged together.

In another embodiment, the engaging members can extend axially from theaxial ends 110, 112, either outward, toward the stationary bodies 106,108, respectively, or inward, away therefrom. Such axially-extendingengaging members can form half of a dog clutch or another type of clutchwith the anti-rotation devices 114, 115 forming the other half of theclutch. In another embodiment, the engaging members and theanti-rotation devices 114, 115 can be axial high-friction surfacesdisposed on the axial ends 110, 112, so as to engage axial high-frictionsurfaces of the anti-rotation devices 114, 115.

In yet another embodiment, either axial or radial, or both, the engagingmembers can be a magnetic target (e.g., laminated ferrous regions) andthe anti-rotation devices 114, 115 can be electromagnets, or vice versa,such that, when engaged, relative rotation of the rotary body 104 andthe stationary bodies 106, 108 can induce eddy currents resistive ofsuch rotation. In yet another embodiment, the engaging members can beprotrusions and/or slots, and the anti-rotation devices 114, 115 caninclude a complementary configuration of slots and/or protrusions.

As will be appreciated from the foregoing description of severalexemplary embodiments for the engaging members of the rotary body 104and the anti-rotation devices 114, 115, a wide variety of embodimentsthereof are contemplated for use consistent with the present disclosure.Further, it will be appreciated that the anti-rotation devices 114, 115need not have the same construction and can include differentconfigurations adapted to provide rotational locking, as will bedescribed in greater detail below. Additionally, the anti-rotationdevices 114, 115 are illustrated as having a smaller outer diameter thanthe bases 116, 117; however, in other embodiments, the anti-rotationdevices 114, 115 can be equal or larger in radius than the bases 116,117.

With continuing reference to FIG. 1, FIGS. 2-4 illustrate schematic,side views of the stabilizer 100, showing exemplary operation thereof,according to an embodiment. For ease of illustration, the stabilizer 100is shown with a single stationary body 108; however, it will beappreciated that the stabilizer 100 can include two stationary bodies106, 108, or more, as described above. Further, the functioning of thetwo stationary bodies 106, 108 can be substantially similar, such that adescription of the functioning of the stationary body 106 can besubstantially duplicative of the functioning of the stationary body 108.

As depicted in FIG. 2, the stabilizer 100 can be deployed into awellbore 200. The wellbore 200 can be formed, for example, by drillingand/or reaming operations. Additionally, the wellbore 200 can bevertical, horizontal, or deviated. Further, the wellbore 200 can includeareas where it departs from cylindrical. An example of such an area canbe a ledge 202, as shown. Especially in open holes, ledges can form fora variety of reasons and can extend partially into the annulus definedbetween the drill string or tubular 102 and the wellbore 200, so as topartially obstruct the wellbore 200.

The outer diameter 113 of the rotary body 104 of the stabilizer 100 canbe configured to engage the wellbore 200, as needed, to centralize thetubular 102 in the wellbore 200. Further, the tubular 102 can berotating relative to the wellbore 200, and the rotary body 104 canrotate with respect to the tubular 102, for example, so as to begenerally non-rotating with respect to the wellbore 200, or, forexample, non-rotating with respect to the tubular 102 unless acted uponby an outside torsional force (e.g., engagement with the wellbore 200).Accordingly, torsional friction forces, slip/stick conditions, and/oraxially oriented drag forces induced by the stabilizer 100 engaging thewellbore 200 can be minimized. At other times, the tubular 102 can benon-rotating, while the rotary body 104 can remain free to rotate withrespect thereto.

When the rotary body 104 encounters the ledge 202, as the tubular 102 isadvanced into (or out of) the wellbore 200 in direction D_(T), the ledge202 can apply an axially-directed force F_(L) on the rotary body 104,resisting progression of the rotary body 104 along with the tubular 102.When the axially-directed force overcomes a biasing force F_(S) appliedby the biasing member 120 (and/or by the biasing member 118, FIG. 1) therotary body 104 can axially translate with respect to the tubular 102 indirection D_(R), toward the stationary body 108.

FIG. 3 illustrates a side, schematic view of the stabilizer 100, withthe rotary body 104 after sliding into engagement with the stationarybody 108, according to an embodiment. By engagement with the stationarybody 108, the rotary body 104 can be prevented from rotation and/oraxial translation with respect to the tubular 102. For example, theaxial end 112 of the rotary body 104 can bear against the base 117 ofthe stationary body 108, such that the base 117 provides an axial stopfor the rotary body 104. Further, the engaging member of the rotary body104 can engage the anti-rotation device 115, resulting in rotationallocking of the anti-rotation device 115 and the rotary body 104. Sincethe anti-rotation device 115 can be coupled to the base 117 so as toresist rotation relative thereto, and the base 117 can be coupled to thetubular 102 so as to resist rotation relative thereto, such rotationallocking of the rotary body 104 to the anti-rotation device 115 canresult in the rotary body 104 being rotationally locked with the tubular102. As the term is used herein, “rotational lock,” and grammaticalvariants thereof, is generally defined to mean that relative rotationbetween two members is resisted and/or avoided unless and untilexcessive force is applied that results in failure of one or more of thecomponents.

With the rotary body 104 rotationally locked with and prevented fromfurther axial translation with respect to the tubular 102, rotationand/or axial advancement of the tubular 102 can be transmitted to therotary body 104. Accordingly, the rotary body 104 can apply a cuttingforce F_(C), which can be at least partially axial and/or at leastpartially torsional, on the ledge 202. The rotary body 104, for example,the axial end 110 thereof, can include the cutting surface 110A, asdescribed above. The cutting surface 110A can cut into, grind, orotherwise remove the ledge 202 by application of the cutting forceF_(C), until the ledge 202 breaks away, grinds apart, or otherwiseyields to allow passage of the rotary body 104. It will be appreciatedthat the axial end 112 can also include a cutting surface, as notedabove, and can function similarly to the axial end 110 when the axialend 112 encounters a ledge.

Referring now to FIG. 4, there is illustrated the stabilizer 100 afterthe ledge 202 has been removed, according to an embodiment. With theledge 202 removed, the axially-directed force F_(L) that was applied bythe ledge 202 on the rotary body 104 to overcome the biasing force F_(S)can be removed. Accordingly, the biasing force F_(S) can act as arestoring force, pushing, pulling, or otherwise urging the rotary body104 away from the stationary body 108, to return the rotary body 104 toits default position, offset from the anti-rotation device 115. As such,the rotary body 104 can once again be free to rotate about the tubular102 and to translate axially, for example, between the stationary bodies106, 108 (FIG. 1).

In some cases, it may be desirable to resist the rotation of the rotarybody 104 with respect to the tubular 102, without the engagement of therotary body 104 with the anti-rotation devices 114, 115 providing theresistance to rotation. For example, in some cases, the engagementbetween the rotary body 104 and the anti-rotation devices 114, 115 mayfail. In other cases, a restriction of the rotation of the rotary body104 about the tubular 102 may be desired without requiring axial forceto be supplied thereto. Accordingly, FIGS. 5A and 5B illustratequarter-sectional views of the stabilizer 100 including a secondaryanti-rotation device, according to an embodiment.

The secondary anti-rotation device can include an inner profile 500 anda gripping member 502. The inner profile 500 can extend radially inwardin the tubular 102 and can be configured to shift axially, for example,from the position shown in FIG. 5A to the position shown in FIG. 5B(i.e., toward the stationary body 106) and/or in reverse. Shifting theinner profile 500 can also cause the inner diameter of the inner profile500 to expand. The gripping member 502 can be or include a set of slips,as shown, whether marking or non-marking, and/or can be or include oneor more pins, screws, protrusions, brake pads, or the like. The grippingmember 502 can be pivotally coupled to the tubular 102, or otherwiseconfigured to move between a retracted position (e.g., FIG. 5A) and anexpanded position (e.g., FIG. 5B).

In an embodiment, when the gripping member 502 is retracted, as shown inFIG. 5A, the inner diameter of the rotary body 104 can slide past thegripping member 502. When expanded, as shown in FIG. 5B, the grippingmember 502 can engage the rotary body 104, either at the inner diameteror at one or both of the axial ends 110, 112. Further, the grippingmember 502 can be coupled to the inner profile 500, such that shiftingof the inner profile 500 causes the gripping member 502 to expand orretract.

In exemplary operation, the inner profile 500 can be configured toreceive a shifting device, which can be a ball 504, as shown, a dart, avalve shifting tool, or any other suitable device deployed into thetubular 102 or otherwise moved into proximity of the inner profile 500.In the depicted embodiment, the ball 504 can have a diameter thatexceeds the inner diameter of the inner profile 500, but can be lessthan the inner diameter of the tubular 102. Accordingly, the ball 504can travel through the tubular 102, for example, motivated by hydraulicforce and catch on the inner profile 500. Continued hydraulic force canbe transmitted through the ball 504 to the inner profile 500, causingthe inner profile 500 to shift and thus expand the gripping member 502.The shifting of the inner profile 500 can include increasing the innerdiameter thereof, and, as such, the ball 504 can continue through thetubular 102 after shifting the inner profile 500, for example, to engagethe inner profile of a subjacent stabilizer.

Accordingly, the secondary anti-rotation device can be engaged torotationally lock the rotary body 104 at the discretion of a wellboreoperator, without requiring a ledge or other wellbore obstruction.Additionally, the secondary anti-rotation device can be employed when itis determined or at least suspected that one or both of theanti-rotation devices 114, 115 has failed or the stabilizer 100otherwise requires additional rotational locking force. A variety ofother embodiments suitable for use in a mechanically-actuated, secondaryanti-rotation device will be readily apparent and are contemplated foruse according to the present disclosure.

FIG. 6 illustrates a quarter-sectional view of the stabilizer 100, withanother embodiment of the secondary anti-rotation device. The secondaryanti-rotation device can include an actuator 600, a battery 601, and agripping member 602. In at least one embodiment, the secondaryanti-rotation device can also include a valve 603 coupled to theactuator 600, such that the actuator 600 can control the position of thevalve 603.

The gripping member 602 can be or include one or more slips, whethermarking or non-marking, pins, teeth, screws, cylinders, protrusions, orthe like. The gripping member 602 can also be one or more brake pads.The gripping member 602 can radially retract to allow the rotary body104 to pass by, rotationally and/or axially, and can expand so as torotationally lock and/or axially restrain the rotary body 104.

The actuator 600 can be any suitable electromechanical or mechanicalactuator, such as a solenoid, servo-motor, mud motor, or the like, andcan be coupled to the battery 601 so as to receive power therefrom. Thebattery 601 can be any suitable type of power storage and/or generatingdevice configured to provide power to the actuator 600 for hours, days,months, or longer. The actuator 600 can be directly, mechanically linkedto the griping member 602, or can be coupled thereto hydraulically viathe valve 603, for example. In such a hydraulic embodiment, actuation ofthe actuator 600 can cause the valve 603 position to modulate, therebyapplying a relatively large hydraulic force on the gripping member 602by application of a relatively small amount of force by the actuator600.

Further, the actuator 600 can receive signals from a controller 604. Thecontroller 604 can be located remotely from the actuator 600, e.g., atthe surface of the wellbore, or at a position between the actuator 600and the surface. In other embodiments, the controller 604 or can belocated proximal the actuator 600, for example, located in the tubular102 near the actuator 600. In an embodiment, the controller 604 can sendsuch signals via wired tubing, or via a wireless connection. Further, insome embodiments, power can be transmitted to the actuator 600, forexample, by running power cables parallel with the tubular 102, whichcan allow the battery 601 to be omitted. In other embodiments, externalpower may not be required, as the actuator 600 can be powered bymovement of fluid in the wellbore.

When singled by the controller 604, the actuator 600 can actuate toexpand the gripping member 602, thereby rotationally locking and/oraxially restraining the rotary body 104 with respect to the tubular 102.Here again, the secondary anti-rotation device can thus be engaged torotationally lock and/or axially restrain the rotary body 104, forexample, at the discretion of a wellbore operator, without requiring aledge or other wellbore obstruction to force the rotary body 104 toengage one of the stationary bodies 106, 108 and/or in a situation wherethe engagement between the rotary body 104 and one of the stationarybodies 106, 108 fails or is otherwise insufficient.

FIG. 7 illustrates a flowchart of a method 700 for stabilizing a drillstring in a wellbore, according to an embodiment. The method 700 canproceed by operation of one or more embodiments of the stabilizer 100and can thus be best understood with reference thereto. The method 700can include biasing a rotary body disposed on a tubular axially apartfrom a stationary body disposed axially adjacent the rotary body, as at702. Such biasing at 702 can include providing a restoring force torestore an axial offset between the rotary body and the stationary body,for example. The method 700 can also include radially engaging awellbore wall with an outer diameter of the rotary body so as tocentralize the drill string, as at 704. The method 700 can furtherinclude sliding the rotary body toward the stationary body in responseto an axial force, as at 706.

Additionally, the method 700 can include rotationally locking the rotarybody and the stationary body, as at 708. Rotationally locking at 708 caninclude engaging the rotary body with an anti-rotation device of thestationary body. The anti-rotation device can be or include one or moreof a variety of devices configured to engage the rotary body andgenerally resist relative rotation between the rotary body and thestationary body. The method 700 can also include removing a ledge withthe rotary body, as at 709, for example, when the rotary body isrotationally locked with the stationary body.

In an embodiment, the method 700 can also include rotating the rotarybody relative the tubular when the rotary body and the stationary bodyare not rotationally locked. This can allow the stabilizer to have areduced torsional and/or axial drag when engaging the wellbore wall, ascompared to stabilizers that are not configured to rotate with respectto the drill string.

In an embodiment, the method 700 can further include actuating asecondary anti-rotation device to rotationally lock the rotary body andthe tubular, as at 710. Actuating the secondary anti-rotation device at710 can include dropping a drop ball, dart, or both in the wellbore.Additionally or alternatively, actuating the secondary anti-rotationdevice at 710 can include signaling an actuator disposed in the wellborewith a controller. Actuating the secondary anti-rotation device at 710can enable the rotary body to be rotationally locked at the option of anoperator and/or if one or more of the first and second anti-rotationdevices fails and/or slips.

The method 700 can also include biasing the rotary body from a secondstationary body disposed axially adjacent the rotary body, such that therotary body can be disposed axially intermediate the first and secondstationary bodies. The method 700 can further include sliding the rotarybody toward the second stationary body in response to a second axialforce, and rotationally locking the rotary body and the secondstationary body.

While the teachings have been described with reference to the exemplaryembodiments thereof, those skilled in the art will be able to makevarious modifications to the described embodiments without departingfrom the true spirit and scope. The terms and descriptions used hereinare set forth by way of illustration only and are not meant aslimitations. In particular, although the method has been described byexamples, the steps of the method can be performed in a different orderthan illustrated or simultaneously. Furthermore, to the extent that theterms “including”, “includes”, “having”, “has”, “with”, or variantsthereof are used in either the detailed description and the claims, suchterms are intended to be inclusive in a manner similar to the term“comprising.” As used herein, the terms “one or more of and “at leastone of with respect to a listing of items such as, for example, A and B,means A alone, B alone, or A and B. Those skilled in the art willrecognize that these and other variations are possible within the spiritand scope as defined in the following claims and their equivalents.

What is claimed is:
 1. A stabilizer apparatus for use in a wellbore,comprising: a rotary body disposed about a tubular; a firstanti-rotation device disposed axially adjacent the rotary body andconfigured to resist rotation and axial translation with respect to thetubular, wherein the rotary body is configured to slide axially toengage the first anti-rotation device and rotationally lock therewith;and a biasing member configured to bias apart the rotary body and thefirst anti-rotation device.
 2. The apparatus of claim 1, furthercomprising a first stationary body comprising the first anti-rotationdevice, the first stationary body being positionally fixed to thetubular.
 3. The apparatus of claim 2, wherein the first stationary bodyprovides an axial stop for the rotary body.
 4. The apparatus of claim 2,wherein the biasing member extends between the first stationary body andthe rotary body.
 5. The apparatus of claim 2, wherein the firststationary body comprises a stop collar fixed to the tubular, a portionintegrally formed with the tubular, or both.
 6. The apparatus of claim1, wherein the rotary body further comprises an axial face defining acutting surface, the cutting surface being configured to remove apartial obstruction of the wellbore when the rotary body engages thefirst anti-rotation device.
 7. The apparatus of claim 1, furthercomprising a second anti-rotation device disposed axially adjacent therotary body such that the rotary body is positioned axially intermediatethe first and second anti-rotation devices, wherein the rotary body isconfigured to axially translate to engage the second anti-rotationdevice and rotationally lock therewith.
 8. The apparatus of claim 7,further comprising a second stationary body comprising the secondanti-rotation device, the second stationary body being positionallyfixed with respect to the tubular.
 9. The apparatus of claim 8, whereinthe biasing member extends between the second stationary body and therotary body.
 10. The apparatus of claim 8, further comprising a secondbiasing member configured to bias apart the second anti-rotation deviceand the rotary body.
 11. The apparatus of claim 1, further comprising asecondary anti-rotation device coupled to the tubular and configured toexpand and engage the rotary body such that the rotary body resistsaxial translation and rotation with respect to the tubular.
 12. Theapparatus of claim 11, wherein the secondary anti-rotation devicecomprises: an inner profile extending into the tubular and configured toreceive a shifting device; and a gripping member coupled to the innerprofile and configured to expand radially outwards to engage the rotarybody, wherein the inner profile is configured to shift by receiving theshifting device and expand the gripping member.
 13. The apparatus ofclaim 11, wherein the secondary anti-rotation device comprises: anactuator configured to receive signals from a controller; and a grippingmember coupled to the tubular, wherein the actuator is configured tocause the gripping member to engage the rotary body when the controllersignals the actuator to actuate.
 14. The apparatus of claim 13, whereinthe actuator hydraulically expands the gripping member.
 15. A method ofstabilizing a drill string, comprising: biasing the rotary body disposedon a tubular axially apart from a first stationary body disposed axiallyadjacent the rotary body; radially engaging a wellbore wall with anouter diameter of the rotary body so as to centralize the drill string;sliding the rotary body toward the first stationary body in response toan axial force; and rotationally locking the rotary body and the firststationary body.
 16. The method of claim 15, wherein biasing the rotarybody includes providing a restoring force to restore an axial offsetbetween the rotary body and the first stationary body.
 17. The method ofclaim 15, further comprising rotating the rotary body relative thetubular when the rotary body and the first stationary body are notrotationally locked.
 18. The method of claim 15, wherein rotationallylocking the rotary body and the first stationary body includes engagingthe rotary body with an anti-rotation device of the first stationarybody.
 19. The method of claim 15, further comprising actuating asecondary anti-rotation device to rotationally lock the rotary body andthe tubular.
 20. The method of claim 19, wherein actuating the secondaryanti-rotation device comprises deploying a shifting device into thewellbore to engage and shift the secondary anti-rotation device.
 21. Themethod of claim 19, wherein actuating the secondary anti-rotation devicecomprises signaling an actuator disposed in the wellbore with acontroller.
 22. The method of claim 15, further comprising: biasing therotary body from a second stationary body disposed axially adjacent therotary body, such that the rotary body is disposed axially intermediatethe first and second stationary bodies; and sliding the rotary bodytoward the second stationary body in response to a second axial force;and rotationally locking the rotary body and the second stationary body.23. The method of claim 15, further comprising removing a ledge with therotary body rotationally locked with the first stationary body.
 24. Astabilizer for a drill string, comprising: a rotary body disposed abouta tubular of the drill string and comprising first and second axialends, and an outer diameter configured to engage a wellbore; a firststationary body disposed axially adjacent the first axial end of therotary body and comprising a first anti-rotation device configured torotationally lock with the rotary body, the first stationary body beingconfigured to resist axial translation and rotation with respect to thetubular; a second stationary body disposed axially adjacent the secondaxial end of the rotary body and comprising a second anti-rotationdevice configured to rotationally lock with the rotary body, the secondstationary body being configured to resist axial translation androtation with respect to the tubular; and one or more biasing membersconfigured to bias the rotary body to a position intermediate andaxially offset from both the first and second stationary bodies, whereinthe rotary body is free to rotate with respect to the tubular unlessrotationally locked with the first stationary body or the secondstationary body.
 25. The stabilizer of claim 24, wherein at least one ofthe first and second anti-rotation devices is configured to slidebetween an inner diameter of the rotary body and the tubular and engagethe inner diameter of the rotary body.
 26. The stabilizer of claim 24,wherein the rotary body comprises a cutting surface on at least one ofthe first and second axial ends, the cutting surface being configured toat least partially remove a ledge of the wellbore when the rotary bodyis rotationally locked with at least one of the first and secondstationary bodies.
 27. The stabilizer of claim 24, wherein the rotarybody is free from bearings disposed on the outer diameter.
 28. Thestabilizer of claim 24, wherein at least one of the first and secondstationary bodies comprises a stop collar fixed to the tubular.
 29. Thestabilizer of claim 24, wherein at least a portion of at least one ofthe first and second stationary bodies is integrally formed with thetubular.
 30. The stabilizer of claim 24, wherein the one or more biasingmembers include: a first biasing member extending axially between therotary body and the first stationary body; and a second biasing membersextending axially between the rotary body and the second stationarybody.
 31. The stabilizer of claim 24, further comprising a secondaryanti-rotation device coupled to the tubular and configured to expand andengage the rotary body such that the rotary body resists axialtranslation and rotation with respect to the tubular.
 32. The stabilizerof claim 31, wherein the secondary anti-rotation device comprises: aninner profile extending into the tubular and configured to receive ashifting tool; and a gripping member coupled to the inner profile andconfigured to expand radially outwards to engage the rotary body,wherein the inner profile is configured to shift by receiving theshifting tool and expand the gripping member.
 33. The stabilizer ofclaim 31, wherein the secondary anti-rotation device comprises: anactuator configured to receive signals from a controller; and a grippingmember coupled to the tubular, wherein the actuator is configured tocause the gripping member to engage the rotary body when the controllersignals the actuator to actuate.